Well fracturing is an often used technique to increase the efficiency and productivity of oil and gas wells. Overly simplified, the process involves the introduction of a fracturing fluid into the well and the use of fluid pressure to fracture and crack the well strata. The cracks allow the oil and gas to flow more freely from the strata and thereby increase production rates in an efficient manner.
There are many detailed techniques involved in well fracturing, but one of the most important is the use of a solid “proppant” to keep the strata cracks open as oil, gas, water and other fluids found in well flow through those cracks. The proppant is carried into the well with the fracturing fluid which itself may contain a variety of viscosity enhancers, gelation agents, surfactants, etc. These additives also enhance the ability of the fracturing fluid to carry proppant to the desired strata depth and location. The fracturing fluid for a particular well may or may not use the same formulation for each depth in the strata.
Proppants can be made of virtually any generally solid particle that has a sufficiently high crush strength to prop open cracks in a rock strata at great depth and temperatures of about 35° C. and higher. Sand and ceramic proppants have proved to be especially suitable for commercial use.
A proppant that is flushed from the well is said to have a high “flow back.” Flow back is undesirable. In addition to closure of the cracks, the flushed proppants are abrasive and can damage or clog the tubular goods used to complete the well, valves and pipelines in downstream processing facilities.
One type of synthetic resin coatings can be used to impart a degree of adhesion to the proppant so that flow back is substantially reduced or eliminated. Such resins can include phenol resin, epoxy resin, polyurethane-phenol resin, furane resin, etc. See published US Patent Application Nos. 2002/0048676, 2003/0131998, 2003/0224165, 2005/0019574, 2007/0161515 and 2008/0230223 as well as U.S. Pat. Nos. 4,920,192; 5,048,608; 5,199,491; 6,406,789; 6,632,527; 7,624,802; and published international application WO 2010/049467, the disclosures of which are herein incorporated by reference.
With some coatings, the synthetic coating is not completely cured when the proppant is introduced into the well. The coated, partially-cured proppants are free flowing, but the coating resin is still slightly reactive. The final cure is intended to occur in situ in the strata fracture at the elevated closure pressures and temperatures found “down hole.”
Such partially cured coating can also exhibit a number of performance issues ranging from:                A lack of storage stability if stored in a hot environment. This type situation could result in a completion of the curing process while in storage making the coated proppant incapable of bonding when placed in the fracture.        Leaching chemicals out of the partially cured coating that could interfere with the viscosity profile of the fluid used to carry the proppant into the fracture or the chemical breaker system that is relied on to reduce the frac fluid viscosity after completion of the fracturing treatment.        Erosion of the partially cured coating when the coated proppant is handled pneumatically in order to place in the field storage bins at the well site.        Premature curing in the fracture due to extended exposure to the elevated temperatures found downhole but before the cracks heal and begin to force the proppant grains into contact with each other.        
A second type of synthetic coating is described as being pre-cured or tempered. In this case the coating is essentially cured during the manufacturing process. This type of coating will strengthen the substrate particle so that it can withstand a higher stress level before grain failure. Such a pre-cured coating with also exhibit the following traits: (1) Excellent storage stability; (2) Minimal chemicals that can be leached out of the coating to interfere with carrier fluid viscosity or breaker systems; and (3) A coating that is resilient to the abrasion of pneumatic handling.
The main limitation of a pre-cured coating is that it cannot create significant particle to particle bonding when placed in the fracture and temperature and closure pressure are applied. This means that a pre-cured coated particle can do little to prevent proppant flowback after the well is opened up to start the clean-up process or to produce the well. Such pre-cured products can also exhibit reductions in bonding capability and/or strength if exposed to elevated temperatures during handling or storage.
Proppants based on polyurethane chemistries have a number of potential advantages over phenol resin systems. Most notably, the reaction rates used to make polyurethane coatings are generally faster than phenol resins, cure at lower temperatures and do not have gaseous emissions that require specialized recovery equipment. The coating step with polyurethanes can be carried out at temperatures of about 10° C. to about 250° C. although temperatures of less than about 110° C. are preferred to minimize emissions during the coating process as well as energy use. Polyurethane coatings can also be performed without the use of solvents, whereas many of the known methods, as a rule, require organic solvents for the resinous coating. The components in polyurethane systems are also generally easier to use and pose lower environmental issues. These factors could reduce the cost to make coated proppants.
Previously described polyurethanes have not, however, achieved widespread adoption due to their performance in the hot, wet, high pressured environment encountered in the fracture. The stability of the coating to this environment, the ability of the coating to prevent particle failure (e.g., by crushing) and to develop strong particle-to-particle bonds, have contributed to poor flowback control and less than desirable fracture conductivity.
Low temperature wells pose certain problems for coated proppants. Prior to the present invention, the only option that was available to the oil and gas well industry for controlling flowback in a well having a low formation temperature, e.g., <140° F. (60° C.) was to use a partially cured, phenolic-coated proppant in combination with a type of plasticizer called a bond “activator”. Without the bond activator, the phenolic coating cured too slowly to generate sufficient bond strength in a reasonable amount of time. The activator plasticizer softens the coating so that the coating can gain some adhesion properties when the coated proppant solids are pushed into contact due to the closure stress from the closing of the fractured strata cracks. This adhesion will never result in a substantial measurable unconfined compressive strength but can result in a somewhat consolidated sample. The activator would be used at concentrations ranging from 5-20 gallons/1000 gallons of fracturing fluid (known as “frac” fluid). While the activator can help the phenolic coated proppant to function (to some degree) in low temperature applications it does have the following issues:                The activator loadings add substantial cost to the treatment.        The activator chemistry can create problems with frac fluid rheology and breakers systems.        The use of an activator does not result in a significant measurable particle to particle bond strength.        The activator is another factor in trying to quantify the effects of a fracturing treatment on the environment.        The phenolic coating also has environmental issues because of the components that can be leached out of the coating (formaldehyde, phenol and hexamethylenetetramine)        